Natural gas is a gaseous fossil fuel consisting primarily of methane but often including significant quantities of ethane, propane, butane, pentane and heavier hydrocarbons. Natural gas produced from subterranean formations may also contain undesirable components such as carbon dioxide, nitrogen, helium and hydrogen sulfide. The undesirable components are usually removed before the natural gas is used as a fuel.
Natural gas hydrates ((NGH) or clathrate hydrates of natural gases, often simply called “hydrates”) form when water and certain gas molecules are brought together under suitable conditions of relatively high pressure and low temperature. Under these conditions the ‘host’ water molecules will form a cage or lattice structure capturing a “guest” gas molecule inside. Large quantities of gas are closely packed together by this mechanism. For example, a cubic meter of methane hydrate contains 0.8 cubic meters of water and up to 172 cubic meters of methane gas. While the most common clathrate on earth is methane hydrate, other gases also form hydrates including hydrocarbon gases such as ethane and propane as well as non-hydrocarbon gases such as CO2 and H2S.
NGH occur naturally and are widely found in sediments associated with deep permafrost in Arctic environments and continental margins at water depths generally greater than 500 meters (1600 feet) at mid to low latitudes and greater than 150-200 meters (500-650 feet) at high latitudes. The thickness of the hydrate stability zone varies with temperature, pressure, composition of the hydrate-forming gas, geologic conditions and other factors. Worldwide, estimates of the natural gas potential of methane hydrates approach 700,000 trillion cubic feet—a staggeringly large figure compared to the 5,500 trillion cubic feet that make up the world's current proven gas reserves.
Most of the natural gas hydrate research to date has focused on basic research as well as detection and characterization of natural gas hydrate deposits which contain primarily methane hydrates. Developing a safe and cost effective method of producing natural gas from natural gas hydrate reservoirs remains a significant technical and economic challenge.
Natural gas hydrate production profile curves are believed to generally follow a characteristic pattern: gas production is initially low and water production is high. After production starts, typically relatively long periods of time (months to many years) pass before the water production declines to a relatively low level and gas production increases to a relatively high level. These relatively high levels of natural gas production rates are then often sustainable for many years.
This inherent production profile has negative economic impacts from a Net Present Value perspective. Expensive production facilities have to be built to handle the processing of fluids from the natural gas hydrate reservoir.
Referring now to the flowchart of FIG. 1, produced fluids from a conventional hydrocarbon reservoir are transported to a production facility, such as located on an offshore platform or on land. The produced fluid may be separated by separation apparatus 11 into predominantly water, oil and gas phases. The gas is treated using conventional gas treatment apparatus 12 to remove contaminants such as CO2 and H2S. The treated gas then may then be compressed and exported such as by using a compressor 13. The compressed gas may be introduced into a pipeline or shipped as compressed natural gas in a tanker. Alternatively, the natural gas may be liquefied and shipped by tanker or else converted by a gas-to-liquids process into a liquid product such as by using a Fischer-Tropsch process. The separated crude oil may be treated by treatment apparatus 14 such as to remove contaminants such as mercury and/or other heavy metals. The treated crude oil may then be stored or exported using apparatus 15. The separated water may be treated using conventional water treatment apparatus, such as is well known by those skilled in the art, so that the water may be disposed of into a body of water if sufficiently treated or else reinjected into a subterranean formation. This list of apparatus employed by a production facility is offered by way of example and certainly is not exhaustive of all the apparatus used in a production facility to process produced fluids from a hydrocarbon bearing reservoir. The term “production facility” refers to any equipment or set of equipment which is used to separate and/or treat produced fluids from a hydrocarbon bearing reservoir such as those pieces of equipment referred to above.
In the case of NGH, these production facilities have to be purchased, installed and operated for potentially years before relatively high gas production rates can be achieved. Unfortunately the time value of money tends to dominate the economic outcome due to the initial cost of production facilities combined with years of operation at a loss while awaiting hydrocarbon production rates to climb above break-even levels. Accordingly, many persons skilled in the arts of hydrocarbon and hydrate extraction currently believe that it is not likely to be economically feasible to develop natural gas hydrate fields. Consequently, there is a need for a method and system for production of natural gas which minimizes this economic challenge in developing and producing natural gas hydrate reservoirs.
As used hereinafter, the term “conventional hydrocarbon reservoir” refers to a reservoir which contains hydrocarbons in a gaseous and/or liquid state as compared to hydrocarbons trapped as clathrate hydrates. Production profile curves for conventional hydrocarbon reservoirs offer a different characteristic pattern from that of production curves associated with natural gas hydrate reservoirs: hydrocarbon production of conventional hydrocarbon reservoirs is initially high and water production is low. Later in the production life of the conventional hydrocarbon reservoir, lesser and lesser quantities of hydrocarbons are produced and more and more water is produced.
While this means there are time value of money benefits to conventional hydrocarbon reservoir production, it is also clear that hydrocarbon production facilities are not fully utilized except for early years at the peak of hydrocarbon production and water production facilities in later years as water production reaches the maximum capacity of the facility. In cases where production from these reservoirs are brought on line generally concurrently, substantial production facilities need to be built to provide sufficient processing capabilities at peak hydrocarbon production. Similarly, substantial water separation and handling facilities must be built to accommodate the large water production which will occur later in the production lives of the reservoirs. It is expensive to add capacity after the initial construction of the production facility so generally all of the needed hydrocarbon and water processing equipment is installed at the beginning of a project. As a result, water processing facilities are underutilized early in the production life of these conventional hydrocarbon reservoirs and hydrocarbon processing facilities are underutilized at later stages of the lives of conventional hydrocarbon reservoirs.
There is a need to minimize the underutilization of production facilities associated with production from conventional hydrocarbon reservoirs as well as a need to minimize the underutilization of production facilities associated with production from natural gas hydrate reservoirs.